In connection with the completion of oil and gas wells, it is frequently necessary to utilize packers in both open and cased bore holes. The walls of the well or casing are plugged or packed from time to time for a number of reasons. For example, a section of the well may be packed off to permit applying pressure to a particular section of the well, such as when fracturing a hydrocarbon bearing formation, while protecting the remainder of the well from the applied pressure.
In a staged frac operation, for example, multiple zones of a formation need to be isolated sequentially for treatment. To achieve this, operators install a fracture assembly 10 as shown in FIG. 1 in a wellbore 12. Typically, the assembly 10 has a top liner packer (not shown) supporting a tubing string 14 in the wellbore 12. Open hole packers 50 on the tubing string 14 isolate the wellbore 12 into zones 16A-C, and various sliding sleeves 20 on the tubing string 14 can selectively communicate the tubing string 14 with the various zones 16A-C. When the zones 16A-C do not need to be closed after opening, operators may use single shot sliding sleeves 20 for the frac treatment. These types of sleeves 20 are usually ball-actuated and lock open once actuated. Another type of sleeve 20 is also ball-actuated, but can be shifted closed after opening.
Initially, all of the sliding sleeves 20 are closed. Operators then deploy a setting ball to close a wellbore isolation valve (not shown), which seals off the downhole end of the tubing string 14. At this point, the packers 50 are hydraulically set by pumping fluid with a pump system 35 connected to the wellbore's rig 30. The build-up of tubing pressure in the tubing string 14 actuates the packers 50 to isolate the annulus 18 into the multiple zones 16A-C. With the packers 50 set, operators rig up fracturing surface equipment and pump fluid down the tubing string 14 to open a pressure actuated sleeve (not shown) so a first downhole zone (not shown) can be treated.
As the operation continues, operators drop successively larger balls down the tubing string 14 to open successive sleeves 20 and pump fluid to treat the separate zones 16A-C in stages. When a dropped ball meets its matching seat in a sliding sleeve 20, fluid is pumped by the pump system 35 down the tubing string 14 and forced against the seated ball. The pumped fluid forced against the seated ball shifts the sleeve 20 open. In turn, the seated ball diverts the pumped fluid out ports in the sleeve 20 to the surrounding annulus 18 between packers 50 and into the adjacent zone 16A-C and prevents the fluid from passing to lower zones 16A-C. By dropping successively increasing sized balls to actuate corresponding sleeves 20, operators can accurately treat each zone 16A-C up the wellbore 12.
The packers 50 typically have a first diameter to allow the packer 50 to be run into the wellbore 12 and have a second radially larger size to seal in the wellbore 12. The packer 50 typically consists of a mandrel about which the other portions of the packer 50 are assembled. A setting apparatus includes a port from the inner throughbore of the packer 50 to an interior cavity. The interior cavity may have a piston that is arranged to apply force either directly to a sealing element or to a rod or other force transmitter that will apply the force to the sealing element.
Typically, when the packer 50 is set, fluid pressure is applied from the surface via the tubular string 14 and typically through the bore of the tubular string 14. The fluid pressure is in turn applied through a port on the packer 50 to the packer's piston. The fluid pressure applied over the surface of the piston is then transmitted to the packer's sealing element to compress the sealing element longitudinally.
Most sealing elements are an elastomeric material, such as rubber. When the sealing element is compressed in one direction it expands in another. Therefore, as the sealing element is compressed longitudinally, it expands radially to form a seal with the well or casing wall.
In some situations, operators may want to utilize comparatively long sealing elements in their packers 50. In these instances, however, as the packer's piston pushes the sealing element to compress the sealing element longitudinally, friction and other forces combine to cause the sealing element to bunch up or otherwise bind near the packer's piston, preventing the sealing element from uniformly compressing longitudinally and thereby preventing the uniform radial expansion of the sealing element. The lack of uniform expansion tends to prevent the packer 50 from forming a seal that meets the operator's expectations, thereby defeating the purpose of utilizing a longer sealing element. For this reason, operators may not use an unset sealing element on a packer 50 that is more than about 24-inches long. Instead, a typical length of an unset seal element is only about 10-inches.
Therefore, a need exists for a packer that is able to utilize an extended length sealing element. The present invention fulfills these needs and provides further related advantages.